Rotary drive apparatus

ABSTRACT

A rotary drive apparatus ( 24 ) for a downhole tool ( 22 ), the rotary drive apparatus ( 24 ) comprising a drive stage ( 36   a ) comprising a rotor ( 40   a ) and a stator ( 42   a ) and a connecting stage ( 38   a ) for connecting to the drive stage ( 36   a ). The connecting stage ( 38   a ) comprises a rotor connector ( 44   a ) suitable for connecting to the rotor ( 40   a ) and a stator connector ( 46   a ) suitable for connecting to the stator ( 42   a ).

FIELD

This relates to a rotary drive apparatus for a downhole tool.

BACKGROUND

The construction of well boreholes involves a number of different operations which can broadly be separated into a number of operational phases.

The first phase involves an operator sequentially landing large diameter casing sections, typically of 21″ (533.4 mm) diameter, 17½″ (444.5 mm) diameter and 13⅜″ (339.7 mm) diameter, in the upper sections of the borehole.

The second phase involves sequentially drilling holes and running smaller diameter casing strings, typically of 9⅝″ (244.5 mm) diameter or 7″ (177.8 mm) diameter or similar.

After the drilling phases, the completion phase is entered and involves running simple or complex completions into the borehole.

The different operational phases place different demands on tools and equipment. For example, the first drilling phases are closer to surface and may be associated with relatively low temperature environment, relatively low pressures, large hole diameters due to washouts and ledges, and relatively low circulating rates, lighter mud weights and generally low dog-leg severity or angular change with incremental depth.

The drilling of these larger sections of the borehole is associated with larger motors and greater torque.

The second drilling phase and the completion phase are associated with deeper and more competent formations, relatively higher temperatures, greater dog-leg severity, smaller diameter holes, higher circulating rates and heavier mud weights.

Reaming tools and equipment have been developed which provide a high-speed reaming capability at the distal end of the casing during deployment. In the event of obstruction of the open hole, such as by swollen shale or unstable borehole cave-ins, drilling fluid (mud) can be pumped through the casing or casing string to energise the reamer and thereby clear the obstruction allowing the casing reaming operation to continue.

Turbine technology supplying high speed rotation of a reamer shoe from a short turbine addresses some of the issues associated with dog-leg severity, and of high temperatures and can provide sufficient torque to re-establish the borehole with the nominal flowrates. Recent improved designs of open path annular turbines have met the rapid drill through requirements to suit the industry.

The torque provided by a basic turbine shows essentially linear dependency on the length of the tool (i.e. the number of turbine stages), the mud weight and the flowrate. As the diameter of an annular turbine is increased the flow area of the turbine increases, and the flow velocities decrease. The approach provided to drill, as distinct from ream as described, with turbines is to provide a gearbox, normally epicyclical, to convert the high speed, low torque turbine output into a low speed higher torque output. This approach is technically challenging. Further, the approach introduces the problem of drilling through the gearbox after landing each casing string. As the mud weight is fixed for most operations, the remaining variable is to add more stages to generate more torque. This is only feasible if the dog-leg severity of the well permits. For the larger diameters of the first drilling phase as described above, the annular turbine solution is therefore limited by the torque from the available flowrate.

The open path annular turbines that have been developed successfully for the required reaming process to land casing have outer diameters slightly greater than the casing to which they are attached. In the case of tightly concentric casings, there can be only a limited increase in outer diameter, and therefore, there will be a requirement to drill through a greater amount of the motor, As such, a suitable motor will require substantially drillable components.

Another challenge of the borehole is dogleg severity, which can stem from tight geometric corners, and unplanned washouts with ledges. Stiff tubulars, and associated stiff motors, have inherent difficulty to negotiate, get over and past such dogleg obstacles.

SUMMARY

According to a first aspect, there is provided a rotary drive apparatus for a downhole tool, the rotary drive apparatus comprising:

a drive stage comprising a rotor and a stator; and

a connecting stage for connecting to the drive stage, wherein at least one of the rotor, the stator and the connecting stage is configured to flex in response to a force applied to the rotary drive apparatus to move the rotary drive apparatus from a first configuration to a second configuration.

In use, the rotary drive apparatus may form part of, or may be coupled to, a downhole tool and run into a borehole as part of a tubing string, such as a casing string, completion string or the like; the rotary drive apparatus configured to drive rotation of the downhole tool, or a component part of the downhole tool, relative to the tubing string to perform a downhole operation in the borehole. In particular embodiments, the rotary drive apparatus may form part of a downhole reaming tool comprising the rotary drive apparatus and a reamer shoe, the rotary drive apparatus configured to drive rotation of the reamer shoe relative to the tubing string to perform a downhole reaming operation, and without the need to rotate to rotate the tubing string from surface.

The connecting stage may be configured to flex in response to a force applied to the rotary drive apparatus to move the rotary drive apparatus from a first configuration to a second configuration.

The provision of a connecting stage which is configured to flex beneficially provides a degree of passive articulation at a distal end of the tubing string which provides hole-finding capability, for example but not exclusively permitting the downhole tool to pass through tortuous well trajectories, soft formations, ledges and any other wellbore deviations that would otherwise create resistance or obstruction while running into the borehole and/or while performing downhole operations.

The connecting stage and the drive stage of the rotary drive apparatus may be configured for coupled together such that the drive stage is disposed between the connecting stage and the downhole tool or downhole tool component to be rotated.

Alternatively, the connecting stage and the drive stage may be configured for coupled together such that the connecting stage is coupled to the downhole tool or downhole tool component to be rotated.

The connecting stage may comprise a rotor connector. The rotor connector may be configured to connect to the rotor of the drive stage. The rotor connector may be configured to flex in response to the force applied to the rotary drive apparatus.

The connecting stage may comprise a stator connector.

The stator connector may be configured to connect to the stator of the drive stage. The stator connector may be configured to flex in response to the force applied to the rotary drive apparatus.

The rotary drive apparatus may be configured to bend at the connecting stage. For example, the rotary drive apparatus may be configured to bend at the connecting stage in preference to bending at the drive stage.

The connecting stage may have a lower stiffness than the drive stage of the rotary drive apparatus.

The connecting stage may have a higher compressibility and/or elasticity relative to the drive stage.

The degree of flexibility of the connecting stage may be controlled by selection of the composition of the material of the stator connector and/or the rotor connector.

The stator connector of the connecting stage may comprise, and/or may be at least partially constructed from, a plastic material.

The stator connector may comprise, and/or may be at least partially constructed from, a polymeric material.

The stator connector of the connecting stage may comprise, and/or may be at least partially constructed from, a composite material.

The stator connector of the connecting stage may comprise, and/or may be at least partially constructed from, a metal material.

The rotor connector of the connecting stage may comprise, and/or may be at least partially constructed from, a plastic material.

The rotor connector may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The rotor connector of the connecting stage may comprise, and/or may be at least partially constructed from, a composite material.

The rotor connector of the connecting stage may comprise, and/or may be at least partially constructed from, a metal material.

The rotor connector and the stator connector may be arranged such that an annulus (“connector annulus”) is formed therebetween. The provision of an annulus between the rotor connector and the stator connector is beneficial because it permits fluid, in particular drilling fluid, drilling mud or the like, to flow between the connecting stage and the drive stage.

The rotor connector may be configured to transmit rotation to/from the rotor of the drive stage.

The rotary drive apparatus may comprise a plurality of the connecting stages.

Where the rotary drive apparatus comprises a plurality of the connecting stages, two or more of the connecting stages may be configured to be connected in series. For example, a first connecting stage of the rotary drive apparatus may be directly connected to a second connecting stage of the rotary drive apparatus, such that the rotor connector of the first connecting stage connects to the rotor connector of the second connecting stage and the stator connector of the first connecting stage is connected to the stator connector of the second connecting stage. The provision of connecting stages that are directly connected to each other permits the degree of flex of the rotary drive apparatus to be tailored or suitably adapted for situations or conditions where a lesser or greater degree of flexibility is required.

Alternatively or additionally, where the rotary drive apparatus comprises a plurality of the connecting stages, two or more of the connecting stages may be configured to connect to respective ends of the drive stage.

At least two of the connecting stages may have the same flexibility, compressibility and/or elasticity.

Alternatively or additionally, at least two of the connecting stages may be of different flexibility, compressibility and/or elasticity.

In particular embodiments, the degree of flexibility, compressibility and/or elasticity of the stator connector may differ from the degree of flexibility, compressibility and/or elasticity of the rotor connector. This is beneficial because the rotor connector and stator connector will have to flex, compress and/or stretch to different degrees when the rotary drive apparatus is in use.

As described above, the drive stage comprises a rotor and a stator.

In particular embodiments, at least one of the rotor and the stator may be configured to flex in response to the force applied to the rotary drive arrangement.

The stator may comprise, and/or may be at least partially constructed from, a plastic material.

The stator may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The stator may comprise, and/or may be at least partially constructed from, a composite material.

The stator may comprise, and/or may be at least partially constructed from, a metal material.

The rotor may comprise, and/or may be at least partially constructed from, a plastic material.

The rotor may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The rotor may comprise, and/or may be at least partially constructed from, a composite material.

The rotor may comprise, and/or may be at least partially constructed from, a metal material, such as steel, aluminium, bronze or the like.

In particular embodiments, the stator may be constructed from an elastomer and the rotor may be constructed from steel.

Alternatively, the rotor may be constructed from an elastomer and the stator may be constructed from steel.

The composition of materials of the connecting stages and/or drive stages of the rotary drive apparatus may be arranged such that there is greater flexibility, elasticity and/or compressibility at the distal end of the rotary drive.

The drive stage may be modular.

The rotary drive apparatus may comprise a plurality of the drive stages.

In embodiments comprising a plurality of drive stages, the drive stages may be configured to directly connect to each other.

For example, a first drive stage may be configured to connect to a second drive stage. The rotor of the first drive stage may be configured to connect to the rotor of the second drive stage and the stator of the first drive stage may be configured to connect to a stator of the second drive stage.

The provision of a plurality of drive stages that are directly connected to each other permits the torque of the rotary drive apparatus to be adapted by configuring the number of drive stages. Further, the provision of a modular drive stage permits the rotary drive apparatus to be configured for higher torque or speed of rotation, as required. Such a modular approach lowers costs and/or simplifies logistics of downhole operations.

The arrangement of the drive stages and the connecting stages may be selected such that there is greater flexibility, elasticity and/or compressibility at the distal end of the rotary drive apparatus.

In particular embodiments, the rotary drive apparatus may comprise more connecting stages than drive stages. This may beneficially increase the overall flexibility of the rotary drive.

The connecting stages may be distributed such that ratio of connecting stages to drive stages is increased towards a distal end of the rotary drive apparatus, that is towards a downhole end of the rotary drive apparatus in use.

Alternatively or additionally, the connecting stages may be distributed such that ratio of connecting stages to drive stages is increased towards a proximal end of the rotary drive apparatus, that is towards an uphole end of the rotary drive.

The rotary drive apparatus may comprise connecting stages of different lengths.

The length of the connecting stages may increase towards the distal of the rotary drive apparatus.

The length of the connecting stages may decrease towards the distal end of the rotary drive apparatus.

The length of the connecting stages may increase towards the proximal end of the rotary drive apparatus.

The length of the connecting stages may decrease towards the proximal end of the rotary drive apparatus.

The lengths of the connecting stages may be beneficially selected such that there is greater flexibility, compressibility and/or elasticity at the distal end of the rotary drive apparatus and progressively less flexibility, compressibility and/or elasticity at the proximal stage of the rotary drive apparatus.

The length of each connecting stage may range from 1 metre to 4 metres, for example from 2 metres to 3 metres.

The rotary drive apparatus may comprise drive stages of different lengths.

The length of the rotor stages may increase towards the distal end of the rotary drive apparatus.

The length of the rotor stages may decrease towards the distal end of the rotary drive apparatus.

The length of the rotor stages may increase towards the proximal end of the rotary drive apparatus.

The length of the rotor stages may decrease towards the proximal end of the rotary drive apparatus.

The length of each drive stage may range from 1 metre to 4 metres, for example from 2 metres to 3 metres.

The composition of materials of the connecting stages and/or drive stages may be arranged such that there is greater flexibility, elasticity and/or compressibility at the distal end of the rotary drive apparatus and progressively less flexibility, elasticity and/or compressibility at the proximal end of the rotary drive.

The drive stage may take a number of different forms.

The drive stage may comprise or define a motor, or other arrangement configured to provide a rotary output to the downhole tool.

The drive stage may be fluid powered.

The drive stage may be powered by fluid, such as drilling mud or the like, and the fluid may be directed to the rotary drive from the surface via an internal bore of a string.

In particular embodiments, the drive stage may comprise a positive displacement motor (PDM).

The provision of a drive stage comprising a positive displacement motor beneficially provides a rotary drive apparatus which can provide a high torque output for driving the downhole tool at the lower flow rates associated with larger casing sizes/diameters As described above, operations with larger diameter casing tubulars are associated with near surface operations, with lower formation temperatures. Lower formation temperatures allow plastic or polymeric material to be used in components of the apparatus, which in turn contribute to the drillability and flexibility of the motor, once target depth is reached. In particular embodiments, both the rotor and the stator may be made partially or completely constructed from an elastomer, plastic or polymeric material. Further, the positive displacement motor may perform more robustly where the circulating fluid, such as mud, containing Lost Circulation Material (LCM), that is material used to reduce and/or prevent the flow of drilling fluid into a weak formation, and which are generally used less often in the final and completion strings at greater depth.

The positive displacement motor may be of the Moineau type. The positive displacement motor may comprise a plurality of chambers. The number of chambers may range from 2 chambers to 8 chambers, although more than 8 chambers may be implemented if required.

The rotor may be helical or substantially helical in shape.

At least one of the rotor and the stator may comprise lobes.

Beneficially, the ratio of the number of lobes on the stator to the number of lobes on the rotor may be selected to produce the desired torque or rotational speed of the drive stage.

Alternatively or additionally, the drive stage may comprise a turbine arrangement. A turbine arrangement may be provided, for example but not exclusively in embodiments utilising smaller diameter casing and completions, due to its inherent pressure response characteristics, high speed, short powerful section, high temperature capability, and/or low vibration operation.

The drive stage may be arranged such that the stator surrounds the rotor. In operation, the stator may be stationary relative to the tubing string, e.g. casing, and the rotor may rotate within the stator.

In particular embodiments, the drive stage may be arranged such that the rotor surrounds the stator. In operation, the stator may be stationary relative to the tubing string, for example casing, and the rotor may rotate around the stator.

In some embodiments, the exterior surface of the rotor may be contoured. The exterior surface of the rotor may comprise one or more flute. In use, the provision of a rotor with one or more flute facilitates passage of fluid, such as drilling fluid, debris and/or cuttings.

At least part of the rotary drive apparatus may be configured to facilitate drilling through the rotary drive apparatus.

The rotary drive apparatus may comprise a hollow centre.

The rotary drive apparatus may comprise an access bore. The access bore may extend through the rotary drive apparatus. The access bore may be configured to permit a further object, such as a cutting structure, to pass through the rotary drive apparatus without or substantially without obstruction.

The connecting stage may be configured to define the access bore.

The drive stage may be configured to define the access bore.

At least one of the rotor connector, the stator connector, the rotor and the stator may be disposed radially outwards from a central longitudinal axis of the connector stage, so as to define the access bore.

Beneficially, the provision of an access bore may facilitate drill through operations to be carried out quickly and efficiently, without the requirement to drill through the workings of the rotary drive apparatus.

Alternatively or additionally, the material of the rotary drive apparatus may be selected to facilitate drill through. For example, at least one of the stator and rotor of the drive stage and the connecting stage may be at least partially constructed from at least one of: a polymeric material; a plastic material; and a composite material to facilitate drill through. However, it will be recognised that other suitable materials may be used, such as bronze or the like, may be used to facilitate drill through.

The rotary drive apparatus may comprise a housing.

The drive stage may be disposed or contained within the housing.

The housing may be configured to flex in response to the force applied to the rotary drive arrangement.

The housing may comprise, and/or may be at least partially constructed from, a plastic material.

The housing may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The housing may comprise, and/or may be at least partially constructed from, a composite material.

The housing may comprise, and/or may be at least partially constructed from, a metal material.

The rotary drive apparatus may comprise a bearing arrangement.

The bearing arrangement may comprise one or more thrust bearing.

A thrust bearing may be operatively associated with the drive stage. The thrust bearing may be disposed between the connecting stage and the drive stage. The thrust bearing may be disposed between the drive stage and the downhole tool or component to be rotated.

In embodiments comprising a plurality of drive stages, a thrust bearing may be disposed between the drive stages.

In embodiments comprising a plurality of connecting stages, a thrust bearing may be disposed between connecting stages.

Such an arrangement beneficially distributes the total thrust across multiple stages leading to lower requirements of bearings and easier drillability.

The thrust bearing may comprise, and/or may be at least partially constructed from, a plastic material.

The thrust bearing may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The thrust bearing may comprise, and/or may be at least partially constructed from, a composite material.

The thrust bearing may comprise, and/or may be at least partially constructed from, a metal material.

The material of the thrust bearing may be selected to facilitate drilling through the bearing.

The bearing arrangement may comprise one or more journal bearing.

Such an arrangement beneficially distributes the total motor radial thrust across multiple stages leading to lower requirements of bearings and easier drillability.

A journal bearing may be operatively associated with the drive stage.

The journal bearing may comprise, and/or may be at least partially constructed from, a plastic material.

The journal bearing may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

The journal bearing may comprise, and/or may be at least partially constructed from, a composite material.

The journal bearing may comprise, and/or may be at least partially constructed from, a metal material.

The material of the journal bearing may be selected to facilitate drilling through the bearing.

The composition of bearing materials may be selected to vary the degree of flexibility of any component of the rotary drive.

The composition of bearing materials may be selected to beneficially improve the ease at which the rotary drive may be drilled through.

The apparatus may comprise, or may be operatively associated with a pressure relief device.

The pressure relief device may be configured to protect the rotary drive apparatus and other downhole equipment, such as a reaming tool, from being exposed to high and potentially unsafe differential pressures and/or pressure surges.

In operation, fluid may be pumped down from surface and into the rotary drive apparatus. The fluid drives the rotary device with the pressure relief device in an inactivated condition, for example with the valve deactivated or the rupture disc unbroken. When running a casing into a well, a pressure relief device can be in an activated condition (for example with a valve open) and fluid can flow from the well though the hollow centre of the rotary device. Further, deploying a reaming tool in operation into the wellbore involves lowering the reaming tool into a wellbore which has been filled with drilling fluid. This movement of the reaming tool through the drilling fluid causes a surging, or pressure build up or pressure reduction, of fluid in the wellbore. This surging, is detrimental to the wellbore wall. In order to reduce this effect the ‘trip in’ running speed must be reduced to an acceptable minimum, resulting in an increase in operating time of rig floor operations. Existing turbine tools have a limited anti-surge capability achieved by the upward flow of drilling fluid through the non-rotating turbine. This may be insufficient to mitigate the detrimental effects of the surging, or fluid friction and/or pressure increase. A dedicated anti-surge valve may be required.

The pressure relief device may be disposed in the access bore of the rotary drive apparatus.

The pressure relief device may take a number of forms.

The pressure relief device may comprise a rupture valve, a rupture disc, or the like.

Alternatively or additionally, the pressure relief device may comprise a valve.

The valve may comprise a relief valve.

The valve may comprise a flapper valve.

In particular embodiments, the valve may comprise a piston pressure release valve. The piston pressure relief valve may beneficially protect downhole equipment from high fluid pressure surges or high fluid pressure-differential surges. The valve may define a safety valve.

The valve may comprise:

a valve body;

an actuator; and

an arrangement for fluid pressure surge mitigation.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a plastic material.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a composite material.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a metal material.

The material of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to facilitate drill through.

The composition of the materials of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to vary the degree of flexibility of the valve and/or the rotary drive apparatus.

The composition of the materials of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to beneficially improve ease of drill through.

The valve body may house the actuator. The valve body may be fixably located within the access bore, and/or within the tubing string. The valve body may be fixed in a position by attachment by a threaded connector or any other mechanical fastener or connector, or by welding, the use of adhesive or other bonding process, or by any other means.

The valve body may comprise a low friction coating. The low friction coating may be applied to the surface of the valve body. The low friction coating may be a fluoropolymer based coating e.g. a Xylan coating, or the like. A low friction coating advantageously permits the actuator to move within the valve body with reduced or minimal friction, and may maintain a low and relatively constant level of friction throughout the lifespan of the valve. Minimising and/or maintaining the friction associated with the movement of the actuator within the valve body is beneficial because it permits reliable configuration of the arrangement for fluid pressure surge mitigation, as will be described below.

The actuator may comprise a face which, in use, may be exposed directly or indirectly to a pressure which may, in use, increase relative to a volume of low pressure and, thus, actuate the valve.

The actuator may comprise a low-friction coating. The low friction coating may be a fluoropolymer based coating e.g. a Xylan coating, or the like.

The actuator may be configured to slidably move within the valve body.

The actuator may retain the valve in a deactivated state in the absence of a pressure or pressure differential equal to or greater than a selected value.

A biasing member, such as a radial spring, may retain the actuator in a position which retains the valve in the deactivated configuration in the absence of the pressure or pressure differential equal to or greater than the selected value.

Application of a pressure or pressure differential greater than a selected value may move the actuator to a position which retains the valve in an activated configuration.

The arrangement for fluid pressure surge mitigation may comprise a quick reaction arrangement. In use, the quick reaction arrangement may provide substantially instantaneous relief of pressure.

The quick reaction arrangement is beneficial because it solves several problems associated with typical safety valve designs. Typical safety valve designs use compression springs as a force mechanism to seal a valve against a valve seat. In the use of such typical safety valve designs, once the high pressure value is applied to the valve or the valve actuator or the likes, only a small flow-by area is available to vent the high pressure. A small flow-by area can lead to high fluid flow velocity jetting with associated rapid valve seat erosion leading to high pressure surges being generated. The valve may comprise a high flow-by area.

The arrangement for fluid pressure surge mitigation may comprise a radially actioned spring loaded detent ball lock mechanism. The radially actioned spring loaded detent ball lock mechanism may allow a pressure differential across the valve to increase to a selected critical value.

The arrangement may comprise one or more ball.

The arrangement may comprise a plurality of balls.

The arrangement may comprise a radially actioned, e.g. spring loaded, detent ball lock mechanism.

In particular embodiments, the arrangement may comprise a plurality of detent ball lock mechanisms circumferentially arranged around the actuator.

The radially actioned spring loaded detent ball lock mechanism may be set to actuate when the pressure differential across the valve increases to the selected critical value. When the pressure differential across the valve increases to the selected critical value, the detent ball device or devices may be configured to move radially outward. This will release the valve to slide axially and move to the activated position.

The activated position may be an open position, which permits the flow of fluid through the valve.

When the pressure differential across the valve decreases below the selected value, the valve may close back to a detent ball reset position. In the detent ball reset position, the valve may define a deactivated configuration. Such an operating cycle may be repeated.

An exemplary configuration of an arrangement for fluid pressure surge mitigation may be to activate the valve when the fluid pressure differential exceeds approximately 9.7 kPa and to deactivate the piston pressure relief valve when the fluid pressure differential is less than 4.8 kPa. The valve may be activated and deactivated or reset numerous times.

The valve may be configuration to be activated and deactivated or reset numerous times by application of primary high pressure values and secondary low pressure values respectively.

The valve may be configured to be activated and deactivated or reset numerous times by application of primary high pressure differential values and secondary low pressure-differential values, respectively.

The valve may be configured to be activated upon the occurrence of the application of the high pressure and/or high pressure differential setting value.

The valve may be configured to be activated instantaneously upon the occurrence of the application of the high pressure and/or high pressure differential setting value.

The valve may provide an instantaneous pressure relief at the moment when the high pressure and/or high pressure differential setting value is applied to the valve.

In other particular embodiments, the valve may comprise an anti-surge valve.

The anti-surge valve may comprise:

a valve body; a valve member disposed in the valve body, the valve member axially moveable relative to the valve body between a first configuration in which fluid passage through the anti-surge valve is prevented and a second configuration in which fluid passage through the anti-surge valve is permitted.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a plastic material.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a composite material.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a metal material.

The material of at least one of the valve body and valve member may be selected to facilitate drilling through.

The material of the materials of at least one of the valve body and valve member may be selected to vary the degree of flexibility of the valve and/or the rotary drive apparatus.

The valve body may be configured for coupling to the downhole tool. The valve body may be situated within and/or at a top and/or a bottom of the downhole tool.

The valve body may be configured for coupling to the tubing string. The valve body may be configured for coupling by a threaded connector or other mechanical fastener or connector, or by welding, the use of adhesive or other binding process, or by any other means or process.

The valve body may form part of the downhole tool or tubing string.

The valve body may comprise a guide pin to guide movement of the valve member relative to the valve body.

The valve body may comprise pin, screw, slotted set screw with long dog points or the likes to restrict movement of the valve member relative to the valve body.

The valve body may comprise a lateral flow passage.

The valve body may comprise a single lateral flow passage.

The valve body may comprise a plurality of the lateral flow passages.

The valve body may be perforated. The valve body may comprise a lateral fluid passage suitable for providing fluid communication between the anti-surge valve and an annulus within the downhole tool and/or any of a casing, a string, a throughbore or a borehole.

The valve body and/or the valve member may comprise a lateral fluid passage suitable for providing fluid communication through the anti-surge valve.

The valve member may be slidably engaged with the valve body.

The valve member may comprise a piston. The piston may be a floating piston.

The valve member may comprise a recess and/or slot within which a guide pin may be located.

The valve body and/or the valve member may comprise a cap. The cap may be detachably affixed to the valve body and/or the valve member by a threaded connector, pressure fitting or other mechanical fastener or connector, or by welding, the use of adhesive or other binding process, or by any other means or process.

The cap may be configured to limit and/or inhibit the range of movement of the valve member.

The valve member may comprise a pressure relief device, such as a rupture disc or the likes. The pressure relief device may be affixed to the valve member or held in place, by the cap. The pressure relief device may be located within the cap. The cap may be substantially cylindrical. The cap may be hollow. The cap and/or the valve member may comprise a retention member. The retention member may be configured to retain the pressure relief device in a fixed position.

The cap and/or the valve member may comprise at least one inflow port. The inflow port may permit the flow of fluid to the valve member.

The at least one inflow port may be circumferentially arranged around the cap, such that fluid may flow from an exterior of the cap, for example from within a throughbore, to an interior of the cap and/or the valve member and/or the valve body.

The at least one inflow port may be sized to limit the rate of fluid flow through the at least one inflow port.

The arrangement of the at least one inflow port on the cap may advantageously protect the rupture disc from contact or high velocity contact with any debris or lost circulation material (LCM) which may be present in fluid pumped or circulated into the throughbore.

The cap may form a seal with the valve body and/or valve member by means or o-rings, such as rubber o-rings, swan seals, and/or by washers, and/or by a pressure fitting, or the like.

The valve may comprise an alignment arrangement. In use, the alignment arrangement may be configured to maintain rotational alignment between the valve member and the valve body.

The alignment arrangement may comprise a guide pin.

The alignment arrangement may comprise a spring guide or spring rod.

The valve may be configured so that the valve member is urged from the first, closed, configuration to the second, open, configuration by fluid flow encountered as the downhole tool travels or is run downhole. The valve may remain in the second configuration during the running-in operation.

The valve may be configured so that the valve member is urged from the second, open, configuration to the first, closed, configuration when the downhole tool is stationary and/or when the downhole tool is in operation and/or when fluid such as drilling fluid is pumped or circulated into the downhole tool.

The valve may be configured so that the valve member remains in the second configuration when the downhole tool is stationary due to the effects of gravity upon the valve member.

Alternatively, the valve may be configured so that the valve member remains in the first configuration when the downhole tool is stationary due a force applied by the spring guide or spring rod.

As described above, the pressure relief device may be configured for single use operation or multiple use operation.

The rotary drive apparatus may be provided in combination with, or form part of, a downhole tool.

As described above, at least one of the rotor, the stator and the connecting stage is configured to flex in response to a force applied to the rotary drive apparatus to move the rotary drive apparatus from a first configuration to a second configuration.

The force applied to the rotary drive apparatus may comprise a force applied to the rotary drive apparatus from surface. For example, the force may be applied via a tubing string, such as a casing string, completion string or other conveyance.

The force applied to the rotary drive apparatus may comprise a force applied to the rotary drive apparatus from within the borehole. For example, the force may be applied by a downhole tractor or the like, located at an uphole location and/or a downhole location relative to the rotary drive apparatus.

According to a second aspect, there is provided a downhole tool comprising the rotary drive according to the first aspect.

The downhole tool may comprise a reaming tool.

The reaming tool may comprise a body adapted for location within a bore, wherein the body comprises at least one reaming member, the body adapted to be selectively coupled to one of a rotor and a stator or a rotor connector and a stator connector of the rotary drive to permit control of the movement of the body by the rotary drive.

The reaming tool may comprise a reaming nose forming a lead end of the reaming tool.

At least one of the body and the reaming nose may further comprise at least one fluid port for directing fluid to the exterior of the reaming tool.

At least one of the body and the reaming nose may be rotationally balanced.

The reaming tool may further comprise a geometric reaming structure formed in, or provided on, at least one of the body and the reaming nose.

The downhole tool or tool string may comprise at least one of: a reaming tool, for use in Reaming In Hole (RIH) operations; an under-reaming tool for use in under-reaming operations; a drill; hole-opener; cutting tool; coring tool; milling tool, excavating tool, or similar tool or device for downhole operations.

According to a third aspect, there is provided a downhole system comprising the rotary drive according to the first aspect. The system may comprise a downhole tool.

The downhole tool may comprise at least one of: a reaming tool, for use in Reaming In Hole (RIH) operations; an under-reaming tool for use in under-reaming operations; a drill; hole-opener; cutting tool; coring tool; milling tool, excavating tool, or similar tool or device for downhole operations.

The downhole system may comprise a tubing string, such as a completion string, wherein the rotary drive or downhole tool is configured to be coupled to the completion string.

The rotary drive apparatus and/or the downhole tool may be powered using fluid supplied, pumped or circulated through the tubing string, or through an inner string e.g. washpipe, within the tubing string.

The downhole system may be configured for running into a borehole on a running string and, in particular embodiments, the running string may comprise a drill pipe string, though any suitable running or conveying member may be used.

The downhole system may be configured for location in the borehole substantially without rotation, thereby reducing or eliminating the risk of damaging the components of the downhole system which are not suited to rotation.

In particular embodiments, a reaming tool may be adapted for location on a distal end of the string, although the tool may alternatively be adapted for location at another location on the string.

According to a fourth aspect of the present invention there is provided a method of constructing a rotary drive apparatus for use with a downhole tool, comprising:

providing a drive stage comprising a rotor and a stator;

providing a connecting stage suitable for connecting to the drive stage, and comprising a rotor connector suitable for connecting to the rotor and a stator connector suitable for connecting to the stator, wherein at least one of the rotor, the stator and the connecting stage is configured to flex in response to a force applied to the rotary drive apparatus to move the rotary drive apparatus from a first configuration to a second configuration; and

connecting the drive stage to the connecting stage.

The method may comprise connecting a rotary drive to at least one other rotary drive. The at least one other rotary drive may be identical or similar to the rotary drive of the first aspect.

The method may comprise connecting the rotary drive to a completion, such as a completion string, or casing string.

In some embodiments, a downhole end of the rotary drive may be connected to the downhole tool or tool string, such as the completion string or casing string.

Alternatively or additionally, an uphole end of the rotary drive may be connected to the downhole tool or tool string, such as the completion string or casing string.

According to a fifth aspect, there is provided a method of reaming a borehole using the rotary drive apparatus of the first aspect.

The method may further comprise pumping or otherwise circulating a fluid into and/or through the rotary drive. Fluid may be directed or otherwise pass through the tool in a downhole direction or an uphole direction.

The method may further comprise pumping or otherwise circulating a fluid into an annulus between a rotor connector and a stator connector of the rotary drive.

The method may further comprise pumping or otherwise circulating a fluid into a space between and a stator of the rotary drive.

According to a sixth aspect, there is provided a rotary drive apparatus for a downhole tool or system, the rotary drive apparatus comprising a positive displacement motor comprising at least one of a plastic and/or composite rotor and a plastic and/or composite stator.

According to a seventh aspect, there is provided a downhole tool comprising the rotary drive apparatus according to the sixth aspect.

According to an eighth aspect, there is provided a downhole system comprising the rotary drive apparatus according to the sixth aspect.

According to a ninth aspect, there is provided a method of reaming a borehole using the rotary drive apparatus of the sixth aspect.

According to a tenth aspect, there is provided a pressure relief device, the pressure relief device comprising a piston pressure relief valve comprising:

a valve body;

an actuator; and

an arrangement for fluid pressure surge mitigation.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a plastic material.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a composite material.

At least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may comprise, and/or may be at least partially constructed from, a metal material.

The material of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to facilitate drill through.

The composition of the materials of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to vary the degree of flexibility of the valve and/or the rotary drive apparatus.

The composition of the materials of at least one of the valve body, actuator and arrangement for fluid pressure surge mitigation may be selected to beneficially improve ease of drill through.

The valve body may house the actuator. The valve body may be fixably located within the access bore, and/or within the tubing string. The valve body may be fixed in a position by attachment by a threaded connector or any other mechanical fastener or connector, or by welding, the use of adhesive or other bonding process, or by any other means.

The valve body may comprise a low friction coating. The low friction coating may be applied to the surface of the valve body. The low friction coating may be a fluoropolymer based coating e.g. a Xylan coating, or the like. A low friction coating advantageously permits the actuator to move within the valve body with reduced or minimal friction, and may maintain a low and relatively constant level of friction throughout the lifespan of the valve. Minimising and/or maintaining the friction associated with the movement of the actuator within the valve body is beneficial because it permits reliable configuration of the arrangement for fluid pressure surge mitigation, as will be described below.

The actuator may comprise a face which, in use, may be exposed directly or indirectly to a pressure which may, in use, increase relative to a volume of low pressure and, thus, actuate the valve.

The actuator may comprise a low-friction coating. The low friction coating may be a fluoropolymer based coating e.g. a Xylan coating, or the like.

The actuator may be configured to slidably move within the valve body.

The actuator may retain the valve in a deactivated state in the absence of a pressure or pressure differential equal to or greater than a selected value.

A biasing member, such as a radial spring, may retain the actuator in a position which retains the valve in the deactivated configuration in the absence of the pressure or pressure differential equal to or greater than the selected value.

Application of a pressure or pressure differential greater than a selected value may move the actuator to a position which retains the valve in an activated configuration.

The arrangement for fluid pressure surge mitigation may comprise a quick reaction arrangement. In use, the quick reaction arrangement may provide substantially instantaneous relief of pressure.

The quick reaction arrangement is beneficial because it solves several problems associated with typical safety valve designs. Typical safety valve designs use compression springs as a force mechanism to seal a valve against a valve seat. In the use of such typical safety valve designs, once the high pressure value is applied to the valve or the valve actuator or the likes, only a small flow-by area is available to vent the high pressure. A small flow-by area can lead to high fluid flow velocity jetting with associated rapid valve seat erosion leading to high pressure surges being generated. The valve may comprise a high flow-by area.

The arrangement for fluid pressure surge mitigation may comprise a radially actioned spring loaded detent ball lock mechanism. The radially actioned spring loaded detent ball lock mechanism may allow a pressure differential across the valve to increase to a selected critical value.

The arrangement may comprise one or more ball.

The arrangement may comprise a plurality of balls.

The arrangement may comprise a radially actioned, e.g. spring loaded, detent ball lock mechanism.

In particular embodiments, the arrangement may comprise a plurality of detent ball lock mechanisms circumferentially arranged around the actuator.

The radially actioned spring loaded detent ball lock mechanism may be set to actuate when the pressure differential across the valve increases to the selected critical value. When the pressure differential across the valve increases to the selected critical value, the detent ball device or devices may be configured to move radially outward. This will release the valve to slide axially and move to the activated position.

The activated position may be an open position, which permits the flow of fluid through the valve.

When the pressure differential across the valve decreases below the selected value, the valve may close back to a detent ball reset position. In the detent ball reset position, the valve may define a deactivated configuration. Such an operating cycle may be repeated.

An exemplary configuration of an arrangement for fluid pressure surge mitigation may be to activate the valve when the fluid pressure differential exceeds approximately 9.7 kPa and to deactivate the PPRV when the fluid pressure differential is less than 4.8 kPa.

The valve may be activated and deactivated or reset numerous times.

The valve may be configuration to be activated and deactivated or reset numerous times by application of primary high pressure values and secondary low pressure values respectively.

The valve may be configured to be activated and deactivated or reset numerous times by application of primary high pressure differential values and secondary low pressure-differential values, respectively.

The valve may be configured to be activated upon the occurrence of the application of the high pressure and/or high pressure differential setting value.

The valve may be configured to be activated instantaneously upon the occurrence of the application of the high pressure and/or high pressure differential setting value.

The valve may provide an instantaneous pressure relief at the moment when the high pressure and/or high pressure differential setting value is applied to the valve.

According to an eleventh aspect, there is provided a method of constructing a pressure relief device according to the tenth aspect, comprising:

providing a valve body;

providing an actuator; and

providing an arrangement suitable for fluid pressure surge mitigation.

According to a twelfth aspect, there is provided a pressure relief device comprising an anti-surge valve for a downhole tool, the anti-surge valve comprising:

a valve body;

a valve member disposed in the valve body, the valve member axially moveable relative to the valve body between a first configuration in which fluid passage through the anti-surge valve is prevented and a second configuration in which fluid passage through the anti-surge valve is permitted.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a plastic material.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a polymeric material, such as an elastomer.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a composite material.

At least one of the valve body and valve member may comprise, and/or may be at least partially constructed from, a metal material.

The material of at least one of the valve body and valve member may be selected to facilitate drilling through.

The material of the materials of at least one of the valve body and valve member may be selected to vary the degree of flexibility of the valve and/or the rotary drive apparatus.

The valve body may be configured for coupling to the downhole tool.

The valve body may be situated within and/or at a top and/or a bottom of the downhole tool.

The valve body may be configured for coupling to the tubing string.

The valve body may be configured for coupling by a threaded connector or other mechanical fastener or connector, or by welding, the use of adhesive or other binding process, or by any other means or process.

The valve body may form part of the downhole tool or tubing string.

The valve body may comprise a guide pin to guide movement of the valve member relative to the valve body.

The valve body may comprise pin, screw, slotted set screw with long dog points or the likes to restrict movement of the valve member relative to the valve body.

The valve body may comprise a lateral flow passage.

The valve body may comprise a single lateral flow passage.

The valve body may comprise a plurality of the lateral flow passages.

The valve body may be perforated. The valve body may comprise a lateral fluid passage suitable for providing fluid communication between the anti-surge valve and an annulus within the downhole tool and/or any of a casing, a string, a throughbore or a borehole.

The valve body and/or the valve member may comprise a lateral fluid passage suitable for providing fluid communication through the anti-surge valve.

The valve member may be slidably engaged with the valve body.

The valve member may comprise a piston. The piston may be a floating piston.

The valve member may comprise a recess and/or slot within which a guide pin may be located.

The valve body and/or the valve member may comprise a cap. The cap may be detachably affixed to the valve body and/or the valve member by a threaded connector, pressure fitting or other mechanical fastener or connector, or by welding, the use of adhesive or other binding process, or by any other means or process.

The cap may be configured to limit and/or inhibit the range of movement of the valve member.

The valve member may comprise a pressure relief device, such as a rupture disc or the likes. The pressure relief device may be affixed to the valve member or held in place, by the cap. The pressure relief device may be located within the cap. The cap may be substantially cylindrical. The cap may be hollow.

The cap and/or the valve member may comprise a retention member. The retention member may be configured to retain the pressure relief device in a fixed position.

The cap and/or the valve member may comprise at least one inflow port. The inflow port may permit the flow of fluid to the valve member.

The at least one inflow port may be circumferentially arranged around the cap, such that fluid may flow from an exterior of the cap, for example from within a throughbore, to an interior of the cap and/or the valve member and/or the valve body.

The at least one inflow port may be sized to limit the rate of fluid flow through the at least one inflow port.

The arrangement of the at least one inflow port on the cap may advantageously protect the rupture disc from contact or high velocity contact with any debris or lost circulation material (LCM) which may be present in fluid pumped or circulated into the throughbore.

The cap may form a seal with the valve body and/or valve member by means or o-rings, such as rubber o-rings, swan seals, and/or by washers, and/or by a pressure fitting, or the like.

The valve may comprise an alignment arrangement. In use, the alignment arrangement may be configured to maintain rotational alignment between the valve member and the valve body.

The alignment arrangement may comprise a guide pin.

The alignment arrangement may comprise a spring guide or spring rod.

The valve may be configured so that the valve member is urged from the first, closed, configuration to the second, open, configuration by fluid flow encountered as the downhole tool travels or is run downhole. The valve may remain in the second configuration during the running-in operation.

The valve may be configured so that the valve member is urged from the second, open, configuration to the first, closed, configuration when the downhole tool is stationary and/or when the downhole tool is in operation and/or when fluid such as drilling fluid is pumped or circulated into the downhole tool.

The valve may be configured so that the valve member remains in the second configuration when the downhole tool is stationary due to the effects of gravity upon the valve member.

Alternatively, the valve may be configured so that the valve member remains in the first configuration when the downhole tool is stationary due a force applied by the spring guide or spring rod.

According to a thirteenth aspect, there is provided a method of constructing a pressure relief device according to the twelfth aspect, comprising:

providing a valve body; and

providing a valve member suitable to be disposed in the valve body, the valve member being axially moveable relative to the valve body between a first configuration in which fluid passage through the anti-surge valve is prevented and a second configuration in which fluid passage through the anti-surge valve is permitted.

It should be understood that the features defined above in accordance with any aspect of the present invention or below relating to any specific embodiment of the invention may be utilised, either alone or in combination with any other defined feature, in any other aspect or embodiment or to form a further aspect or embodiment of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects will now be described, by way of example only, with reference to the accompanying drawings, in which:

FIG. 1 is a schematic side view of a downhole system according to an embodiment of the present invention;

FIG. 2A is a side view of a reaming tool according to an embodiment of the present invention, suitable for use in the downhole system of FIG. 1;

FIG. 2B is a part-cutaway side view of the reaming tool shown in FIG. 2A;

FIG. 3A is a perspective view of the rotary drive apparatus of the reaming tool shown in FIGS. 2A and 2B;

FIG. 3B is a cross sectional view of a drive stage of the rotary drive apparatus shown in FIG. 3A;

FIG. 3C is a longitudinal section view A-A of the drive stage shown in FIG. 3B;

FIG. 4A is a perspective view of another embodiment of the rotary drive apparatus of the reaming tool shown in FIGS. 2A and 2B;

FIG. 4B is a cross sectional view of a drive stage of the rotary drive apparatus shown in FIG. 4A;

FIG. 4C is a longitudinal section view B-B of the drive stage shown in FIG. 4B;

FIG. 5A is a cross sectional view of a drive stage according to another embodiment;

FIG. 5B is a longitudinal section view C-C of the drive stage shown in FIG. 5A;

FIG. 6A is a cross sectional view of a drive stage according to another embodiment;

FIG. 6B is a longitudinal section view D-D of the drive stage shown in FIG. 6A;

FIG. 7A is a cross sectional view of a drive stage according to another embodiment;

FIG. 7B is a longitudinal section view E-E of the drive stage shown in FIG. 7A;

FIG. 8A is a cross sectional view of a piston pressure relief valve according to an embodiment of the invention, in a deactivated position;

FIG. 8B is a sectional view of an arrangement for fluid pressure surge mitigation of the relief valve shown in FIG. 8A;

FIG. 9A is a cross sectional view of the piston pressure relief valve shown in FIG. 8A, in an activated position;

FIG. 9B is a sectional view of the arrangement for fluid pressure surge mitigation, in the activated position;

FIG. 10A is a cross sectional view of the piston pressure relief valve, in the deactivated position;

FIG. 10B is a cross sectional view of the piston pressure relief valve shown in FIG. 10A, in the activated position;

FIG. 11 shows an anti-surge valve to an embodiment of the invention, in a closed position;

FIG. 12 shows the anti-surge valve of FIG. 11;

FIG. 13 shows the anti-surge valve of FIG. 14, in an open position;

FIG. 14 is a perspective view of an anti-surge valve according to an alternative embodiment, in a closed position;

FIG. 15 is a cross sectional view of the anti-surge valve of FIG. 14, in the closed position;

FIG. 16 is a perspective view of the anti-surge valve of FIG. 14, in an open position;

FIG. 17 is a cross sectional view of the anti-surge valve of FIG. 14, in the open position;

FIG. 18 is a cross sectional view of the anti-surge valve of FIG. 17 in the open position according to an embodiment of the invention; and

FIG. 19 is a cross sectional view of an anti-surge valve of FIG. 17 in the closed position according to an embodiment of the invention.

DETAILED DESCRIPTION

Referring first to FIG. 1 of the accompanying drawings, there is shown a schematic side view of a downhole system 10 according to an embodiment of the present invention, the system 10 configured to be run into a borehole 12. As can be seen from FIG. 1, the borehole 12 has been drilled and lined with bore-lining tubulars 14. The distalmost bore-lining tubular 14 comprises a liner which terminates in a shoe 16. In the embodiment shown in FIG. 1, the liner comprises a 7⅝ inch (193.68 mm) diameter tubular, though any suitable tubulars may be used. The borehole 12 has subsequently been extended beyond the shoe 16, in the illustrated embodiment in a substantially horizontal direction, this unlined section 18 of the borehole 12 extending through a hydrocarbon-bearing formation 20. It will be readily understood that the unlined section 18 of the borehole 12 may be of any required length, and may extend for several kilometres through the formation.

A reaming tool 22 is provided at a distal leading end of the downhole system 10 and the reaming tool 22 is run into the borehole 12 with the downhole system 10. The reaming tool 22 comprises a rotary drive apparatus 24, and a reamer shoe 26 comprising a reaming body 28 and a reaming nose 30. In use, fluid is directed to the rotary drive apparatus 24 to drive rotation of the reamer shoe 26 to facilitate reaming of the borehole 12 by the reaming tool 22.

As described further below, the rotary drive apparatus 24 is configured to flex in response to a force applied to the rotary drive apparatus 24 exceeding a selected threshold, this providing a degree of passive articulation at a distal end of the system 10 which provides hole-finding capability, for example but not exclusively permitting the system 10 to pass through tortuous well trajectories, soft formations, ledges and any other wellbore deviations that would otherwise create resistance or obstruction while running into the borehole 12 and/or while performing downhole operations.

FIGS. 2A and 2B show an exemplary reaming tool 22 for use in the downhole system 10 shown in FIG. 1. FIG. 2A shows the reaming tool 22 in a first configuration and FIG. 2A shows the reaming tool 22 in a second, flexed, configuration, the reaming tool 22 being configured to be reconfigurable from the first configuration to the second configuration in response to the force applied to the reaming tool 22.

As described above with reference to FIG. 1, reaming tool 22 comprises rotary drive apparatus 24 connected to reaming shoe 26 having reaming body 28 and reaming nose 30. As shown in FIGS. 2A and 2B, reaming shoe 26 comprises a number of radially extending and circumferentially arranged blades 32 for reaming the borehole section 18. A number of circumferentially arranged ports 34 are provided in the reaming shoe 26, the ports 34 in the illustrated embodiment being provided in the nose 30. In use, fluid may be directed through the ports 34 to lubricate passage of the reaming tool 22 through the borehole 12 and/or to assist in the removal of debris and cuttings during operation.

The rotary drive apparatus 24 forms the power section of the reaming tool 22 and has a drive stage 36 a and a connecting stage 38 a for connecting to the drive stage 36 a. The drive stage 36 a comprises a rotor 40 a and a stator 42 a and the connecting stage 38 a comprises a rotor connector 44 a and a stator connector 46 a.

In the illustrated embodiment, the rotor 40 a is disposed radially inwards of the stator 42 a such that in use the rotor 40 a rotated within the stator 42 a. However, it will be recognised that in other embodiments the rotor 40 a may alternatively be disposed radially outwards of the stator 42 a and configured in use to rotate around the stator 42 a.

The exemplary arrangement shown in FIGS. 2A and 2B shows two connecting stages 38 a, 38 b and three drive stages 36 a, 36 b, 36 c. However, it will be understood that a rotary drive apparatus according to other embodiments may comprise a single drive stage and a single connecting stage, or any number of drive stages and connecting stages.

As shown in the cut-away portion of FIG. 2B, in the illustrated embodiment, the connecting stage 38 a is flexible, that is at least one of the rotor connector 44 a and the stator connector 46 a is configured to flex in response to the force applied to the reaming tool 22 exceeding the selected threshold. The rotor connector 44 a and the stator connector 46 a are, in the rotary drive apparatus 24, formed by plastic or composite tubing having a lower stiffness than conventional metallic bore-lining tubulars, the cut-away portion of FIG. 2B showing the relatively rigid rotor 40 a and stator 42 a of drive stages 36 a, 36 b, 36 c connected to the flexible connecting stages 38 a, 38 b.

As noted above, the reaming tool 22 shown in FIGS. 2A and 2B exemplifies the hole finding capability of the reaming tool 22 and/or the system 10 due to the rotary drive apparatus 24 flexing due to the flexing of only the connecting stages 38 a, 38 b. However, in other embodiments the ability to flex the rotary drive apparatus 24 may alternatively or additionally be provided by the drive stage, at least one of the rotor and the stator being configured to flex in response to the applied force exceeding a selected threshold.

Referring now also to FIGS. 3A to 3C of the accompanying drawings, there is shown an exemplary rotary drive apparatus 24 of the reaming tool 22. As described above, the illustrated rotary drive apparatus 24 comprises two connecting stages 38 a, 38 b (connecting stage 38 a being shown in FIG. 3A) and three drive stages 36 a, 36 b, 36 c (drive stages 36 a,36 b being shown in FIG. 3A).

As shown in FIGS. 3A-3C, the stators 42 a, 42 b have a substantially cylindrical exterior surface and the rotors 40 a, 40 b are hollow, such that the interior surface of the rotors 40 a, 40 b form a substantially tubular shape, forming an access bore 48 located about an axis X. The diameter of the stators 42 a, 42 b as measured from the exterior surface is larger than the diameter of the rotors 40 a, 40 b as measured from the interior surface of the rotor. The rotors 40, 40 b are arranged such that they are surrounded by the stators 42 a, 42 b along the axis X. The exterior surface of the rotors 40 a, 40 b comprises elongated lobes 50 and the interior surface of the stators 42 a, 42 b comprise lobes 52 which together form substantially helical shapes. A passage 52 between the rotors 40 a, 40 b and the stators 42 a, 42 b permits the flow of fluid. In the illustrated embodiment, the rotors 42 a, 42 b comprise four lobes 50 and the stators 42 a, 42 b comprise five lobes 52.

As described above, the rotors 40 a, 40 b are hollow, such that fluid may flow within the rotors 40 a, 40 b. In operation, drilling fluid, such as mud, may be pumped, circulated or otherwise directed into the passage 52 between the rotors 40 a, 40 b and the stators 42 a, 42 b to drive rotation of the drive stages of the rotary drive apparatus 24.

In use, the shoe is adapted to rotate at a selected speed, although higher speeds may be used where appropriate, thus facilitating efficient reaming of the wellbore. The nose is constructed from a metallic material, such as aluminium or brass, though other materials such as ferrous materials, or ceramics may be used where appropriate. Fluid, such as drilling fluid or mud or the like, is directed from the drive stage to the reamer shoe and through the ports to assist in removing material from the bore. The fluid may then be recirculated to surface via an annulus (not shown) between the shoe and the bore. The ribs engage the interior surface of the wellbore or tubular component, rotation of the shoe reaming the wellbore to the required dimension and surface texture. Abrasive particles provided on the ribs and nose further assist in performing the operation. The number of lobes may be selected to produce the desired torque or rotational speed of the rotary drive. The stator always has one more lobe than the rotor when the rotary drive is a positive displacement motor. The number of complete twists that the substantially helical shaped and circumferentially distributed lobes of the exterior surface of the rotor makes in a single drive stage may be selected to produce a desired torque at a given fluid flow rate. On completion of the reaming operation, the shoe, the drive stages and the connecting stages can be drilled through to permit extension of the bore or permit location of tools or pipe though the bore. At least some of the components of the reaming shoe are sacrificial, that is they are suitable for drilling through.

It will be understood that the rotary drive apparatus may take a number of different forms.

Referring now to FIG. 4A to 4C of the accompanying drawings, there is shown an alternative rotary drive apparatus 124 of the reaming tool 22. The illustrated rotary drive apparatus 124 comprises two connecting stages 138 a, 138 b (connecting stage 138 a being shown in FIG. 4A) and three drive stages 136 a, 136 b, 136 c (drive stages 136 a, 136 b being shown in FIG. 4A).

As shown in FIGS. 4A-4C, the stators 142 a, 142 b have a substantially cylindrical exterior surface and the rotors 140 a, 140 b are hollow, such that the interior surface of the rotors 140 a, 140 b form a substantially tubular shape, forming an access bore 148 located about an axis X′. The diameter of the stators 142 a, 142 b as measured from the exterior surface is larger than the diameter of the rotors 140 a, 140 b as measured from the interior surface of the rotor. The rotors 140 a, 140 b are arranged such that they are surrounded by the stators 42 a, 42 b along the axis X′. The exterior surface of the rotors 140 a, 140 b comprises elongated lobes 150 which form substantially helical shapes. A passage 152 between the rotors 140 a, 140 b and the stators 142 a, 142 b permits the flow of fluid. As described above, the rotors 140 a, 140 b are hollow, such that fluid may flow within the rotors 140 a, 140 b. In operation, drilling fluid, such as mud, may be pumped, circulated or otherwise directed into the passage 152 between the rotors 140 a, 140 b and the stators 142 a, 142 b to drive rotation of the drive stages of the rotary drive apparatus 124.

In this embodiment, the rotors 140 a, 140 b comprise seven lobes 150 and the stators comprise eight lobes 152. Such an arrangement serves to minimise the cross-sectional area of the passage 152 between the rotors 140 a, 140 b and the stators 142 a, 142 b. The reduced cross-sectional area of the passage 152 results is a greater fluid flow velocity and greater motor speed and/or torque. The reduced cross-sectional area of the stators 140 a, 140 b also requires less material for manufacture and results in an apparatus which is lighter and/or more economical to manufacture.

The number of lobes may be selected to produce the desired torque or rotational speed of the drive stage. The number of complete twists that the substantially helical shaped and circumferentially distributed lobes of the interior surface of the stator makes in a single drive stage may be selected to produce a desired torque at a given fluid flow rate. A higher number of lobes increases the torque characteristics. The higher number of lobes leads to larger diameter rotor and lower wall-thickness stator. This may allow the rotor to be hollow.

Referring now to FIG. 5A to 7B of the accompany drawings, there are shown alternative rotary drive apparatus 324, 424 and 524 of the reaming tool 22.

In the embodiment shown in FIGS. 5A and 5B, rotor 340 comprises four lobes 350 and the stator 342 comprises five lobes 352. The stator 342, 342 also has substantially helical shaped and circumferentially distributed lobes 54 on its exterior surface. The provision of the substantially helical shaped and circumferentially distributed lobes 54 on the exterior surface of the stator 242 beneficially increases the flow rate of fluid within the annulus between the apparatus 324 and the borehole 12.

In the embodiment shown in FIGS. 6A and 6B, the apparatus 424 comprises a housing 56 and the rotor 440 has a circular cross-section (equivalent to a single lobe) and the stator 442 has an elongated circular shaped cavity defined by its interior surface (equivalent to a two lobes). The ratio of rotor lobes to stator lobes is 1:2, resulting in a high speed, low torque configuration.

In the embodiment shown in FIGS. 7A and 7B, the rotor 540 comprises five lobes 550 and the stator 542 comprises six lobes 552. Moreover, as described above, the rotor may in some embodiments be disposed radially outwards of the stator and configured to rotated around the stator and in the embodiment shown in FIGS. 7A and 7B, the rotor 540 is disposed radially outwards of the stator 542.

FIG. 8A is a cross sectional view of a piston pressure relief valve 1000, in a deactivated position. In the deactivated position, the valve actuator 1001 is positioned within the valve body 1002 such that the valve piston 1005 seals the radial openings 1015, thus preventing the flow of fluid through the piston pressure relief valve 1000. The o-rings 1012, 1013 ensure the valve actuator 1001 forms a seal with the valve body 1002. A radial spring or coil spring 1006 retains the valve actuator 1001 in a position which retains the valve 1000 in the deactivated state in the absence of a pressure or pressure differential equal to or greater than a selected value. Slotted set screws 1011 with long dog points are positioned to restrict movement of the valve actuator 1001 and piston valve beyond a defined position. The valve body 1002 comprises a collar or spring support 1007 to support the radial spring or coil spring 1007. The valve actuator 1001 comprises a top collar or top spring support 1008 to support the radial spring or coil spring 1007. The top collar or top spring support 1008 is maintained in position by screws 1009. A valve guide pin 1014 guides the valve piston 1005 when the valve actuator 1001 is moving. The valve guide pin 1014 beneficially ensures that there is no rotational movement of the valve actuator 1001 which could have the detrimental effect of misaligning the indentations on the valve actuator 1001 with the valve balls 1004. The exemplary arrangement shows an arrangement for fluid pressure surge mitigation comprising radial spring plugs 1010. The radial spring plugs 1010 are positioned circumferentially around the valve actuator 1001. Associated with each radial spring plug 1010 is a ball spring 1003 and a valve ball 1004. In the deactivated state, the valve ball or ball 1004 is held by the ball spring 1003 in an associated indentation or circumferential groove in the valve actuator 1001. The ball 1004, thus, inhibits movement of the valve actuator 1001 until a force is applied to the valve actuator 1001 sufficient to compress the ball spring 1003, permitting the valve ball 1004 to exit the associated indentation or circumferential groove in the valve actuator 1001.

FIG. 8B is a sectional view of an arrangement for fluid pressure surge mitigation of the valve shown in FIG. 8A, in the deactivated position. This exemplary arrangement shows the provision of five radial spring plugs 1010, ball springs 1003 and valve balls 1004.

FIG. 9A is a cross sectional view of the piston pressure relief valve 1000 of FIG. 8A, shown in an activated position. The valve actuator 1001 is positioned such that the radial openings 1015 are aligned with openings 1016 in the valve piston 1005, thus permitting the flow of fluid through the piston pressure relief valve 1000. The ball 1004, has moved radially outwards from the indentation of circumferential groove in the valve actuator 1001, compressing the ball spring 1003, as a result of a pressure force applied to the valve 1000. FIG. 9B, which is a sectional view of the arrangement for fluid pressure surge mitigation of FIG. 8B, in an activated position according, more clearly shows the position of the valve balls 1004 and ball springs 1003 when the valve 1000 is in the activated state.

FIGS. 10A and 10B are cross sectional views of the piston pressure relief valve 1000, in the deactivated and activated positions respectively, and showing the positioning of the valve 1000 within a housing 1021.

Referring to FIG. 11 of the drawings, there is shown an anti-surge valve, generally indicated by reference numeral 2000, according to an embodiment of the present invention.

As shown in FIG. 11, the anti-surge valve 2000 comprises a valve body 2002 and a valve member 2004. The valve body 2002 comprises two distinct sections, 2002 a, 2002 b. First section 2002 a of the valve body 2000 is affixed to the top of the downhole tool. The second section 2002 b of the valve body 2000 is affixed to the first section 2002 a by means of shear pins 2006. The second section 2002 b houses the valve member 2004. A seal is maintained between the first section 2002 a and the second section 2002 b by means of an o-ring 2008.

The valve member 2004 is axially moveable relative to the valve body 2002 between a first, open configuration in which fluid passage through the anti-surge valve 2000 is prevented and a second, closed configuration in which fluid passage through the anti-surge 2000 valve is permitted. The valve body comprises a cap 2001. The cap 2001 is affixed to the valve body 2002. The cap 2001 comprises inflow ports 2011, permitting fluid to flow between the throughbore 2013 and the interior 2014 of the anti-surge valve. The valve body is substantially cylindrical.

The valve body comprises a plurality of circumferentially arranged inflow ports 2010.

The anti-surge valve 2000 comprises a rupture disc assembly. The rupture disc assembly 2009 is detachably affixed to the valve member 2004 by means of a retainer nut 2003.

A seal is maintained between the valve member 2004 and the valve body 2002 by a wiper seal 2007.

The operation of the anti-surge valve can be seen from FIGS. 12 and 13, which show the direction of the flow of fluid relative to the anti-surge valve 2000.

The anti-surge valve 2000 is designed to operate under hydraulic flow. When the reamer tool is run into the wellbore, the anti-surge valve 2000 is directed or forced to be in the open position, as shown in FIG. 13. When running in the wellbore, fluid in the wellbore flows upward into the valve body 2002 and pushes against the valve member 2004. This moves the valve member 2004 into the open position and the fluid flows through the anti-surge valve 2000 through the in-flow ports 2010. By this operation, the anti-surge valve 2000 will remain open during the running-in operation. When the running-in operation is stopped, for example to add additional lengths of casing to the string, the valve member 2004 may close by gravity. On resumption of the running-in operation the anti-surge valve 2000 it will open as previously described.

When the drilling fluid is pumped under pressure into the wellbore 2013 the anti-surge-valve 2000 is directed or forced by flow and pressure differential to move to a closed position, as shown in FIG. 13. Arrows 2012 denote the direction of fluid flow. The valve member 2004 is moved by fluid flow and pressure differential into the closed position, and forming a seal by a circular knife edge feature 2018 against the interior flat face of valve body 2002 and will remain in this position under fluid flow. It can be seen that the valve member 2004 is positioned such that it obstructs the flow of fluid through the flow through ports 2010.

Referring now to FIGS. 14 to 19, there is shown an anti-surge valve, generally denoted 3000, according to an alternative embodiment. As shown, the anti-surge valve 3000 comprises a valve body 3001 which houses a valve member 3002. The valve member 3002 may slide within the valve body 3001, configuring the anti-surge valve 3000 to be in an open or closed configuration. The range of movement of the valve member is limited by at least two parallel pins 3008. This differs from the embodiment of FIG. 11, where the range of movement of the valve member 2004 is limited by a cap 2001 affixed to the valve body 2002. In the second embodiment, cap 3004 is fixedly attached directly to the valve member 3002. The cap 3004 comprises inflow ports 3020, permitting fluid to flow between the throughbore and the interior of the anti-surge valve 3000. The movement of the valve member 3002 within the valve body 3001 is guided by at least two spring guides 3003. The spring guides 3003 are affixed to the valve body, and slidably inserts into an associated slot in the valve member 3002. A collar 3021 on the valve member inhibits movement of the spring 3023 of the spring guide 3003 into the slot. A seal is maintained between the valve member 3002 and the valve body 3001 by a swan seal 3007.

When the reamer tool is run into the wellbore, the anti-surge valve 3000 is directed or forced to be in the open position.

The valve body 3001 comprises a plurality of circumferentially arranged inflow ports 3025. The inflow ports 3025 are arranged such that the valve body is, effectively, perforated.

The anti-surge valve 3000 is designed to operate under hydraulic flow.

When running in the throughbore, fluid in the throughbore flows upward into the valve body 3001 and pushes against the valve member 3002. This moves the valve member 3002 in a path guided by the spring guides 3003 into the open position, wherein further movement of the valve member 3002 in the opening direction is inhibited by the parallel pins 3008, and the fluid flows through the anti-surge valve through the in-flow ports 3025. Similarly, when fluid is pumped under pressure into the throughbore the anti-surge-valve 3000 is directed or forced by flow and pressure differential to move to a closed position.

FIG. 18 is a cross sectional view of the anti-surge valve 3000, the closed position, and shows the anti-surge valve 3000 positioned at the top of a downhole tool 3100, such as the reaming tool 22 described above. The anti-surge valve 3000 is located within a perforated section of inner-casing 3200. It can be seen that the valve member 3002 is positioned such that it obstructs the flow of fluid through the flow through ports 3025.

FIG. 19 shows a cross-sectional view of the anti-surge valve 3000, in the open configuration, and also illustrates the path of the flow of fluid that would results in the anti-surge valve 3000 moving to the closed position. Fluid pumped or circulated into the throughbore flows through the screen or perforated side walls of the casing into an annulus 3050, and subsequently into the downhole tool 3100. The fluid in the throughbore is pressurised, primarily for the purposes of powering the downhole tool 3100. A restricted amount of fluid may initially flow through the inflow ports 3025 of the anti-surge valve. In this scenario, the fluid pressure within the anti-surge valve and within at least the top of the downhole tool is less than the pressure in the throughbore outside the anti-surge valve 3000, resulting in a pressure differential. When the pressure differential is sufficient to overcome the compression force of the guide-springs 3003, the valve member 3002 will move to a closed position.

It should be understood that the embodiments described are merely exemplary of the present invention and that various modifications may be made without departing from the scope of the invention. 

What is claimed is:
 1. A rotary drive apparatus for a downhole tool, the rotary drive apparatus, comprising: a drive stage comprising a rotor and a stator; and a connecting stage for connecting to the drive stage, wherein at least one of the rotor, the stator and the connecting stage is configured to flex in response to a force applied to the rotary drive apparatus to move the rotary drive apparatus from a first configuration to a second configuration.
 2. The apparatus of claim 1, wherein the connecting stage comprises a rotor connector configured to connect to the rotor of the drive stage.
 3. The apparatus of claim 2, wherein the rotor connector is configured to flex in response to the force applied to the rotary drive apparatus.
 4. The apparatus of claim 1, wherein the rotor connector is at least partially constructed from at least one of: a polymeric material; a plastic material; and a composite material.
 5. The apparatus of claim 1, wherein the connecting stage comprises a stator connector configured to connect to the stator of the drive stage.
 6. The apparatus of claim 5, wherein the stator connector is configured to flex in response to the force applied to the rotary drive apparatus.
 7. The apparatus of claim 5, wherein the stator connector is at least partially constructed from at least one of: a polymeric material; a plastic material; and a composite material.
 8. The apparatus of claim 1, comprising a plurality of the connecting stages.
 9. The apparatus of claim 8, wherein two or more of the connecting stages are configured to be connected in series.
 10. The apparatus of claim 8, wherein two or more of the connecting stages are configured to connect to respective ends of the drive stage.
 11. The apparatus of claim 8, wherein at least two of the connecting stages are of different flexibility, compressibility and/or elasticity.
 12. The apparatus of any preceding claim, wherein at least one of the stator and the rotor are at least partially constructed from: a polymeric material; a plastic material; and/or a composite material.
 13. The apparatus of claim 1, wherein the drive stage is fluid powered.
 14. The apparatus of claim 1, wherein the drive stage comprises or defines a motor.
 15. The apparatus of claim 14, wherein the drive stage comprises a positive displacement motor.
 16. The apparatus of claim 1, wherein the drive stage is arranged such that the rotor surrounds the stator.
 17. The apparatus of claim 1, comprising a plurality of the drive stages.
 18. The apparatus of claim 1, wherein at least part of the rotary drive apparatus is configured to facilitate drilling through the rotary drive apparatus.
 19. The apparatus of claim 1, comprising an access bore therethrough.
 20. The apparatus of claim 1, comprising or operatively associated with a pressure relief device.
 21. The apparatus of claim 20, wherein the pressure relief device comprises a valve, comprising: a valve body; an actuator; and an arrangement for fluid pressure surge mitigation.
 22. The apparatus of claim 20, wherein the pressure relief device comprises an anti-surge valve comprising: a valve body; a valve member disposed in the valve body, the valve member axially moveable relative to the valve body between a first configuration in which fluid passage through the anti-surge valve is prevented and a second configuration in which fluid passage through the anti-surge valve is permitted.
 23. A pressure relief device comprising an anti-surge valve for a downhole tool, the anti-surge valve comprising: a valve body; and a valve member disposed in the valve body, the valve member axially moveable relative to the valve body between a first configuration in which fluid passage through the anti-surge valve is prevented and a second configuration in which fluid passage through the anti-surge valve is permitted. 